Compositions for enhanced oil recovery

ABSTRACT

Disclosed herein are compositions and methods for increasing recovery of hydrocarbon compounds from hydrocarbon-containing subterranean fractured rock formations. Novel emulsions and fracturing fluids are provided. The fracturing fluids convert oil-wet rocks to water-wet, yet exhibit a low tendency of composition components to sorb to the rock. The fracturing fluids do not cause formation of emulsions with hydrocarbon compounds within the subterranean fractured rock formations.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent ApplicationNo. 62/121,885, filed Feb. 27, 2015, entitled “Compositions for EnhancedOil Recovery,” and U.S. Provisional Patent Application No. 62/169,890,filed Jun. 2, 2015, entitled “Compositions for Enhanced Oil Recovery,”each of which is incorporated by reference herein, in the entirety andfor all purposes.

FIELD OF THE INVENTION

The present invention relates to compositions and methods for increasedrecovery of crude oil from a subterranean hydrocarbon-containingformation.

BACKGROUND

Hydraulic fracturing is a well-stimulation technique in whichsubterranean rock is fractured by a hydraulically pressurized fracturingfluid typically made by combining water, an hydraulic fracturingproppant (conventionally sand or aluminum oxide), and additive chemicalsthat modify subterranean flow, subterranean interfacial tension, and/orprovide other effects. A hydraulic fracture is formed by pumping thefracturing fluid into a wellbore at a rate sufficient to increasepressure at the target depth to exceed that of the fracture gradient(pressure gradient) of the rock. When the hydraulic pressure is removedfrom the well, the hydraulic fracturing proppants lodge within thecracks to hold the fractures open. Hydrocarbon compounds such as naturalgas and petroleum are recovered via the cracks in thehydrocarbon-containing deep-rock formations. Hydraulic fracturingtechniques can be used to form a new well and can also be used to extendthe life of an existing conventional oil well.

Chemical additives including surfactants have been added to fracturingfluids in hydraulic fracturing processes to increase recovery ofhydrocarbon compounds from subterranean hydrocarbon-containingformations. The surfactants can act to lower the interfacial tensionbetween the fracturing fluid and the oil trapped within the fractures inthe reservoir and can change the wettability of the reservoir rock,thereby increasing the yield of hydrocarbon compounds released from therock fractures. However, many conventional surfactants and surfactantblends adsorb substantially onto the rock surfaces, depleting thesurfactant quickly at the expense of deeper-lying fracture surfaces.Additionally, many injected surfactants facilitate underground emulsionformation between the hydrocarbon compounds and the fracturing fluid,which retards or prevents recovery of the hydrocarbon compounds.

Further, conventional chemical surfactants and mixtures thereof areoften unstable or insoluble in the high temperature and/or high totaldissolved solids water sources encountered in some subterraneanreservoirs. For example, in some reservoirs temperatures in excess of60° C. are encountered; temperatures can be as high as 250° C.Additionally, underground water is often characterized as having hightotal dissolved solids, such as about 4 wt % total dissolved solids andas much as about 35 wt % total dissolved solids. In some cases, asubstantial portion of the dissolved solids are ionic (one or moresalts).

Thus, there is a need in the industry for compositions that reduce theinterfacial tension between a fracturing fluid and the oil trappedwithin the fractured subterranean rock formations without adsorbingstrongly to the rock surfaces. There is a need in the industry forcompositions that reduce the interfacial tension between a fracturingfluid and the oil trapped within the fractured subterranean rockformations in high temperature environments. There is a need in theindustry for compositions that reduce the interfacial tension between afracturing fluid and the oil trapped within fractured rock formations insubterranean environments having water sources that include high totaldissolved solids. There is a need in the industry for compositions thatincrease the yield of hydrocarbon compounds recovered from fracturedsubterranean rock formations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a plot of interfacial tension as a function of temperature forfracturing fluids of the invention.

FIG. 2 is plot of interfacial tension as a function of temperature andconcentration for fracturing fluids of the invention in 2 wt % KCl.

FIG. 3 is plot of interfacial tension as a function of temperature andconcentration for fracturing fluids of the invention in 12 wt % KCl.

FIG. 4 is plot of interfacial tension as a function of KCl concentrationfor fracturing fluids of the invention.

FIG. 5 is plot of surface tension as a function of time for fracturingfluids of the invention in 2% KCl at 300° F. (149° C.) at 200 psi (1379kPa).

SUMMARY

Disclosed herein are compositions and methods for increased recovery ofcrude oil from a subterranean hydrocarbon-containing formation.Disclosed herein are emulsions that are useful to form fracturing fluidsfor injection into one or more subterranean reservoirs.

The emulsions of the invention are diluted with a high total dissolvedwater source, such as produced water, to form the fracturing fluids ofthe invention. The fracturing fluids of the invention are injected intooil-containing reservoirs. The fracturing fluids are thermally stablewhen subjected to underground conditions including temperatures of about60° C. to 120° C. Upon injection, rock surfaces contacted by thefracturing fluids changes from oil-wettable to water-wettable. Yet theemulsion components of the fracturing fluids exhibit a low tendency toadsorb onto the rock. The fracturing fluids further substantially lowerthe interfacial energy between the fluid and the hydrocarbons present inthe reservoir. Yet the fracturing fluids also inhibit formation ofemulsions in underground fracturing fluid flows. The fracturing fluidsexhibit improved sweeping efficiency and proppant clean-up performanceunder gravitational flow conditions when compared to conventionalfracturing fluids. The fracturing fluids of the invention substantiallyincrease the yield of hydrocarbon products such as crude oil or shaleoil from underground reservoirs when injected therein. The fracturingfluids of the invention and are particularly useful for increasing theyield of hydrocarbon products in reservoirs where high temperatures areencountered underground.

Disclosed herein are compositions comprising about 98 wt % to 99.999 wt% of a water source comprising high total dissolved solids; one or moreoil phase surfactants, the oil phase surfactants characterized asnonionic and having a combined HLB of less than about 9, one or morecoupling agents, one or more water phase surfactants, wherein the waterphase surfactants are nonionic, soluble or dispersible in water, andchemically different from the one or more oil phase surfactants, one ormore ionic surfactants, a clay stabilizer, and water.

Also disclosed herein is a composition comprising about 98 wt % to99.999 wt % of a water source comprising high total dissolved solids;one or more coupling agents; one or more water soluble or dispersiblenonionic surfactants; one or more zwitterionic surfactants; one or moreanionic surfactants, and optionally one or more additional ionicsurfactants. In some embodiments, the emulsion is shelf stable. In someembodiments the composition is a fracturing fluid, the fracturing fluidcomprising about 99 wt % to 99.999 wt % of a water source. In someembodiments the water source is a high temperature water source, a hightotal dissolved solids water source, or a high temperature, high totaldissolved solids water source. In some embodiments, the compositionscomprise one or more additives, the additives comprising one or moreviscosifying agents, solvents, alkali, flow back aids, non-emulsifiers,friction reducers, breakers, crosslinking agents, biocides, proppants,or mixtures thereof.

Also disclosed herein is a method of increasing recovery of crude oilfrom a subterranean hydrocarbon-containing formation, the methodcomprising: forming an emulsion, the emulsion comprising one or more oilphase surfactants, the oil phase surfactants characterized as nonionicand having a combined HLB of less than about 9; a coupling agent; one ormore water phase surfactants, wherein the water phase surfactants arenonionic, soluble or dispersible in water, and chemically different fromthe one or more oil phase surfactants; one or more ionic surfactants;one or more clay stabilizers, and about 40 wt % to 80 wt % water;contacting the emulsion with a water source to form a fracturing fluid;injecting the fracturing fluid into a subterraneanhydrocarbon-containing formation; and collecting a hydrocarbon from thesubterranean hydrocarbon-containing formation. In some embodiments, theinjecting is into a first wellbore connected to the subterraneanhydrocarbon-containing formation, and the collecting is from a secondwellbore that is connected to the subterranean hydrocarbon-containingformation. In other embodiments, the injecting and the collecting arecarried out in the same wellbore.

Also disclosed herein is a method of increasing recovery of crude oilfrom a subterranean hydrocarbon-containing formation, the methodcomprising: forming an emulsion, the emulsion comprising one or morecoupling agents, one or more water soluble or dispersible nonionicsurfactants, one or more zwitterionic surfactants, one or more anionicsurfactants, and optionally one or more additional ionic surfactants;contacting the emulsion with a high total dissolved solids water sourceto form a fracturing fluid, the fracturing fluid comprising about 98 wt% to 99.99 wt % of the high total dissolved solids water source;injecting the fracturing fluid into a subterraneanhydrocarbon-containing formation; and collecting a hydrocarbon from thesubterranean hydrocarbon-containing formation. In some embodiments, thewater source is contacted with the emulsion at a temperature of about60° C. to 250° C. In some embodiments the contacting is carried outcontemporaneously with the injecting; in other embodiments, thecontacting is carried out prior to the injecting.

Other objects and features will be in part apparent and in part pointedout hereinafter.

DETAILED DESCRIPTION

Definitions

As used herein, the term “ionic surfactant” means a water soluble orwater dispersible molecule having cationic, anionic, or zwitterionicfunctionality.

As used herein, the term “nonionic surfactant” means surfactant moleculecharacterized by the absence of cationic, anionic, or zwitterionicfunctionality.

As used herein, the term “emulsion” means a composition including atleast water and a surfactant present in the water in an amountsufficient to surpass the critical micelle concentration (cmc). In someembodiments, an emulsion is a microemulsion. Microemulsions arecharacterized as emulsions that are transparent and thermodynamicallystable.

As used herein, the term “water source” means a source of watercomprising, consisting essentially of, or consisting of fresh water, tapwater, well water, deionized water, distilled water, produced water,municipal water, waste water such as runoff water, “gray” water, ormunicipal waste water, treated or partially treated waste water,brackish water, or sea water, or a combination of two or more such watersources as determined by context. In some embodiments, a water sourceincludes one or more salts, ions, buffers, acids, bases, surfactants, orother dissolved, dispersed, or emulsified compounds, materials,components, or combinations thereof. In some embodiments, a water sourceincludes about 0 wt % to 35 wt % total dissolved solids. In some suchembodiments, the total dissolved solids are substantially non-polymericsolids. In some such embodiments, the dissolved solids comprise, consistessentially of ionic compounds. The term “waterbased” or “watersolution” generally refers to a composition including a water source.The term “saline” or “salinity” refers to a water source wherein aportion, in some embodiments a substantial portion, of the dissolvedsolids are salts. Generally and as determined by context, the term“water source” includes high total dissolved solids water sources, hightemperature water sources, and high total dissolved solids, hightemperature water sources.

As used herein, the term “high temperature” means about 60° C. to 120°C., as specified or determined by context.

As used herein, the term “high total dissolved solids” refers to a watersource comprising at least about 4 wt % non-polymeric solids dissolvedtherein, and in embodiments up to about 35 wt % non-polymeric solidsdissolved therein.

As used herein, the term “stable” as applied to an emulsion means akinetically stable emulsion that absent any force applied, temperaturechange, or chemical added, is or is capable of being substantially freeof coagulation, plating out, precipitation, gross coalescence of phases(conventionally referred to as “separation”) or any other evidence ofinstability conventionally associated with emulsions for at least about24 hours at about 20° C. Where the emulsion is a microemulsion, theemulsion is also thermodynamically stable. As used herein, the term“storage stable” as applied to an emulsion means that the emulsion isstable after at least six months of storage at temperatures betweenabout −25° C. to 60° C.

As used herein, the term “optional” or “optionally” means that thesubsequently described component, event or circumstance may but need notbe present or occur. The description therefore discloses and includesinstances in which the event or circumstance occurs and instances inwhich it does not, or instances in which the described component ispresent and instances in which it is not.

As used herein, the term “about” modifying, for example, the quantity ofan ingredient in a composition, concentration, volume, temperature,time, yield, flow rate, pressure, and like values, and ranges thereof,employed in describing the embodiments of the disclosure, refers tovariation in the numerical quantity that can occur, for example, throughtypical measuring and handling procedures used for making compounds,compositions, concentrates or use formulations; through inadvertenterror in these procedures; through differences in the manufacture,source, or purity of starting materials or ingredients used to carry outthe methods, through standard operating machine error, and likeproximate considerations. The term “about” also encompasses amounts thatdiffer due to aging of a formulation with a particular initialconcentration or mixture, and amounts that differ due to mixing orprocessing a formulation with a particular initial concentration ormixture. Where modified by the term “about” the claims appended heretoinclude equivalents according to this definition.

As used herein, the term “substantially” means “consisting essentiallyof”, as that term is construed in U.S. patent law, and includes“consisting of” as that term is construed in U.S. patent law. Forexample, a solution that is “substantially free” of a specified compoundor material may be free of that compound or material, or may have aminor amount of that compound or material present, such as throughunintended contamination or incomplete purification. A “minor amount”may be a trace, an unmeasurable amount, an amount that does notinterfere with a value or property, or some other amount as provided incontext. A composition that has “substantially only” a provided list ofcomponents may consist of only those components, or have a trace amountof some other component present, or have one or more additionalcomponents that do not materially affect the properties of thecomposition. Additionally, “substantially” modifying, for example, thetype or quantity of an ingredient in a composition, a property, ameasurable quantity, a method, a value, or a range, employed indescribing the embodiments of the disclosure, refers to a variation thatdoes not affect the overall recited composition, property, quantity,method, value, or range thereof in a manner that negates an intendedcomposition, property, quantity, method, value, or range. Where modifiedby the term “substantially” the claims appended hereto includeequivalents according to this definition.

Compositions of the First Embodiment

Disclosed herein are compositions for use in the recovery of hydrocarboncompounds from hydrocarbon-containing subterranean fractured rockformations. In a first embodiment, the compositions are emulsions. Insome such embodiments, the emulsions are microemulsions. The emulsionscomprise, consist essentially of, or consist of (1) one or more oilphase surfactants, the oil phase surfactants characterized as nonionicand having a combined HLB of less than about 9, (2) a coupling agent,(3) one or more water phase surfactants, wherein the water phasesurfactants are nonionic, soluble or dispersible in water, andchemically different from the one or more oil phase surfactants, (4) oneor more ionic surfactants, (5) one or more clay stabilizers, and (6)water.

Suitable oil phase surfactants usefully employed in the emulsions of theinvention comprise, consist essentially of, or consist of one or morenonionic surfactants having an HLB of about 9 or less, or a combined HLBof about 9 or less.

Surfactants are often characterized by HLB. High HLB values indicategood water or polar solvent solubility of the surfactant while low HLBvalues are indicative of good solubility in non polar systems, such asoils. For nonionic surfactants, HLB is calculated using the Griffinformula:

HLB=20×MWH/(MWH+MWL)=wt % hydrophile/5

where MWH=mol. wt. of hydrophile

-   -   MWL=mol. wt. of hydrophobe (lipophile)

Thus, for example, a C10 ethoxylated alcohol bonded to 8 ethylene oxiderepeat units has an HLB of 13.83:

Hydrophobe: CH₃(CH₂)₉—OH; MW=158. Hydrophile: [CH₂CH₂O]₈; MW=352.Therefore HLB=20×352/ (352+158)=13.83.

Examples of suitable oil phase surfactants include alkoxylated alcohols,alkoxylated alkylphenols, glycerol esters, glycol esters, polyethyleneglycol esters, polyglycerol esters, and sorbitol esters, andcombinations of these. In embodiments, the alkoxylated alcohols includeethoxylated, propoxylated, and ethoxylated propoxylated alcohols whereinthe alcohols include 6-20 carbons in linear, branched, or cyclicconformation and the alkoxy functionality includes an average of 1-6moles of ethylene oxide, propylene oxide, or a combination thereof.Glycerol, glycol, polyethyleneglycol, polyglycerol, and sorbitol estersare formed from acids having 6-20 carbons in linear, branched, or cyclicconformation. Suitable oil phase surfactants have an HLB of less thanabout 9, for example about 2 to 9, or about 3 to 9, or about 4 to 9, orabout 5 to 9, or about 6 to 9, or about 7 to 9, or about 2 to 8, orabout 2 to 7, or about 2 to 6, or about 2 to 5, or about 2 to 4, orabout 3 to 8, or about 4 to 8, or about 5 to 8, or about 6 to 8, orabout 3 to 7, or about 4 to 7, or about 5 to 7. Mixtures of two or moresuch surfactants are also suitably employed in the emulsions of theinvention. One of skill will understand that the HLB of suchcombinations is an average of the contribution of each surfactant in themixture, wherein that the combined HLB of the mixture of oil phasesurfactants is about 9 or less as indicated above.

The amount of oil phase surfactants present in the emulsions of theinvention is about 0.1 wt % to about 35 wt % based on the total weightof an emulsion, for example about 0.5 wt % to 35 wt %, or about 1.0 wt %to 35 wt %, or about 1.5 wt % to 35 wt %, or about 2.0 wt % to 35 wt %,or about 5.0 wt % to 35 wt %, or about 10 wt % to 35 wt %, or about 0.1wt % to 30 wt %, or about 0.1 wt % to 25 wt %, or about 0.1 wt % to 20wt %, or about 1.0 wt % to 30 wt %, or about 1.5 wt % to 30 wt %, orabout 2.0 wt % to 30 wt %, or about 2.0 wt % to 25 wt % based on thetotal weight of the emulsion.

Suitable coupling agents employed in the emulsions of the inventioncomprise, consist essentially of, or consist of water miscible solventsand mixtures of two or more water miscible solvents. The coupling agentsdo not destabilize the emulsions. In some embodiments, the couplingagents increase stability of the emulsions. In some embodiments, thecoupling agent is fully miscible with water; that is, all possiblecoupling agent:water ratios are miscible. In other embodiments, thecoupling agent is miscible with water at least up to about 20:1water:coupling agent by volume, or about 10:1, about 9:1, about 8:1,about 7:1, about 6:1, about 5:1, about 4:1, about 3:1, about 2:1, about1:1, about 1:2, about 1:3, about 1:4, about 1:5, about 1:6, about 1:7,about 1:8, about 1:9, about 1:10, about 1:20 water:coupling agent byvolume, or ranges between any of these two ratios, such as between about20:1 and 1:20, between 5:1 and 2:1, and the like.

Suitable coupling agents comprise, consist essentially of, or consist oflinear, branched, or cyclic aliphatic alcohols having 1 to 6 carbonatoms, diols having 1 to 6 carbon atoms, alkyl ethers of alkyleneglycols wherein the alkyl moiety has 1 to 6 carbon atoms (e.g., ethyleneglycol mono-n-butyl ether) polyalkylene glycols, and mixtures thereof.Also useful as coupling agents are glycol and glycerol based acetals andketals, such as those formed from the condensation of e.g. glycerol withformaldehyde, acetone, or oxocarboxylic acids, semialdehydes, and estersthereof such as levulinic acid or an alkyl levulinate. Examples ofuseful coupling agents include methanol, ethanol, glycerol, and ethyleneglycol.

The total amount of coupling agents included in the emulsions of theinvention is about 0.1 wt % to 20 wt % based on the total weight of anemulsion, for example about 0.5 wt % to 20 wt %, or about 1.0 wt % to 20wt %, or about 2.0 wt % to 20 wt %, or about 3.0 wt % to 20 wt %, orabout 4.0 wt % to 20 wt %, or about 5.0 wt % to 20 wt %, or about 6.0 wt% to 20 wt %, or about 7.0 wt % to 20 wt %, or about 8.0 wt % to 20 wt%, or about 9.0 wt % to 20 wt %, or about 10 wt % to 20 wt %, or about0.1 wt % to 19 wt %, or about 0.1 wt % to 18 wt %, or about 0.1 wt % to17 wt %, or about 0.1 wt % to 16 wt %, or about 0.1 wt % to 15 wt %, orabout 0.1 wt % to 14 wt %, or about 0.1 wt % to 13 wt %, or about 0.1 wt% to 12 wt %, or about 0.1 wt % to 11 wt %, or about 0.1 wt % to 10 wt%, or about 5 wt % to 20 wt %, or about 5 wt % to 15 wt % based on thetotal weight of the emulsion.

Suitable water phase surfactants employed in the emulsions of theinvention comprise, consist essentially of, or consist of one or morenonionic surfactants that are soluble or dispersible in water and arechemically different from the one or more oil phase surfactants. Inembodiments, the water phase surfactant is one or more surfactantsselected from the group comprising, consisting essentially of, orconsisting of alkoxylated alcohols and alkoxylated alkyl phenols havingan HLB greater than about 10, for example about 10 to 20, or about 10 to18, or about 10 to 16, or about 10 to 14, or about 11 to 20, or about 11to 18, or about 11 to 17, or about 11 to 16, or about 11 to 15, or about11 to 14, or about 11 to 13, and mixtures of these compounds.

The amount of water phase surfactants employed in the emulsions of theinvention totals about 0.1 wt % to to 10 wt % based on the total weightof an emulsion, or about 0.5 wt % to 10 wt %, or about 1.0 wt % to 10 wt%, or about 1.5 wt % to 10 wt %, or about 2.0 wt % to 10 wt %, or about2.5 wt % to 10 wt %, or about 3.0 wt % to 10 wt %, or about 0.5 wt % to9 wt %, or about 0.5 wt % to 8 wt %, or about 0.5 wt % to 7 wt %, orabout 0.5 wt % to 6 wt %, or about 0.5 wt % to 5 wt %, or about 0.5 wt %to 4 wt %, or about 0.5 wt % to 3 wt %, or about 1.0 wt % to 5 wt %, orabout 1.5 wt % to 5 wt %, or about 2 wt % to 5 wt %, or about 1 wt % to4 wt %, or about 1.5 wt % to 4 wt %, or about 2 wt % to 4 wt % based onthe total weight of the emulsion.

Suitable ionic surfactants employed in the emulsions of the inventioncomprise, consist essentially of, or consist of one or more amphotericmolecules having anionic, cationic or zwitterionic functionality and atleast one linear, branched or cyclic hydrocarbon moiety having 6 to 20carbons. Examples of suitable ionic surfactants include linearalkylbenzene sulfonic acid, alkyl benzene sulfonate, alkyl sulfonates,alkyl sulfates, alkyl ether sulfates, alkyl ammonium halides, alkyl arylammonium halides, imidazolium, cocoamidopropyl betaine, cocodimethylbetaine, and alkyl amine oxides.

The amount of ionic surfactants employed in the emulsions of theinvention totals about 1 wt % to 20 wt % based on the total weight of anemulsion, for example about 1 wt % to 19 wt %, or about 1 wt % to 18 wt%, or about 1 wt % to 17 wt %, or about 1 wt % to 16 wt %, or about 1 wt% to 15 wt %, or about 1 wt % to 14 wt %, or about 1 wt % to 13 wt %, orabout 1 wt % to 12 wt %, or about 1 wt % to 11 wt %, or about 1 wt % to10 wt %, or about 2 wt % to 20 wt %, or about 3 wt % to 20 wt %, orabout 4 wt % to 20 wt %, or about 5 wt % to 20 wt %, or about 6 wt % to20 wt %, or about 7 wt % to 20 wt %, or about 8 wt % to 20 wt %, orabout 9 wt % to 20 wt %, or about 10 wt % to 20 wt %, or about 2 wt % to15 wt %, or about 5 wt % to 15 wt %, or about 7 wt % to 15 wt %, orabout 7 wt % to 12 wt % based on the total weight of the emulsion.

Suitable clay stabilizers employed in the emulsions of the inventioncomprise, consist essentially of, or consist of quaternary ammonium saltpolymers having molecular weights of about 500 g/mol to 10,000 g/mol,choline chloride, inorganic salts, and mixtures thereof. Inorganic saltsusefully employed as clay stabilizers include KCl, CaCl₂, and MgCl₂.Additional clay stabilizers useful in the emulsions of the invention arelisted athttp://booksite.elsevier.com/samplechapters/9780123838445/9780123838445.pdf.

The amount of clay stabilizer employed in the emulsions of the inventiontotals about 1 wt % to 25 wt % based on the total weight of an emulsion,for example about 2 wt % to 25 wt %, or about 3 wt % to 25 wt %, orabout 4 wt % to 25 wt %, or about 5 wt % to 25 wt %, or about 6 wt % to25 wt %, or about 7 wt % to 25 wt %, or about 8 wt % to 25 wt %, orabout 9 wt % to 25 wt %, or about 10 wt % to 25 wt %, or about 11 wt %to 25 wt %, or about 12 wt % to 25 wt %, or about 13 wt % to 25 wt %, orabout 14 wt % to 25 wt %, or about 15 wt % to 25 wt %, or about 1 wt %to 24 wt %, or about 1 wt % to 23 wt %, or about 1 wt % to 22 wt %, orabout 1 wt % to 21 wt %, or about 1 wt % to 20 wt %, or about 1 wt % to19 wt %, or about 1 wt % to 18 wt %, or about 1 wt % to 17 wt %, orabout 1 wt % to 16 wt %, or about 1 wt % to 15 wt %, or about 5 wt % to20 wt %, or about 10 wt % to 20 wt % based on the total weight of theemulsion.

The water employed to form the emulsions of the invention is a watersource. The water source comprises or consists essentially of water,wherein the water comprises 0 wt % to about 35 wt % total dissolvedsolids. In some embodiments, the water source is tap water. The amountof water source employed in the emulsions is about 30 wt % to 95 wt % ofthe total weight of an emulsion, for example about 35 wt % to 95 wt %,or about 40 wt % to 95 wt %, or about 45 wt % to 95 wt %, or about 50 wt% to 95 wt %, or about 55 wt % to 95 wt %, or about 60 wt % to 95 wt %,or about 30 wt % to 90 wt %, or about 30 wt % to 85 wt %, or about 30 wt% to 80 wt %, or about 30 wt % to 75 wt %, or about 30 wt % to 70 wt %,or about 30 wt % to 65 wt %, or about 30 wt % to 60 wt %, or about 40 wt% to 90 wt %, or about 40 wt % to 80 wt %, or about 50 wt % to 80 wt %,or about 50 wt % to 70 wt % based on the total weight of the emulsion.

Optionally, one or more nonionic oil soluble demulsifiers are added toimprove efficiency of dilution of the emulsions during injection intothe subterranean reservoir. Where present, the nonionic oil solubledemulsifiers are selected from the group comprising, consistingessentially of, or consisting of polyethylenimine alkoxylates,alkoxylated alkylphenol formaldehyde resins, alkoxylated amine-modifiedalkylphenol formaldehyde resins, ethylene oxide/propylene oxidecopolymers, crosslinked ethylene oxide/propylene copolymers, andmixtures thereof. Where employed, the nonionic oil soluble demulsifiersare present in the emulsions at about 0.01 wt % to 5 wt % based on thetotal weight of an emulsion, for example about 0.05 wt % to 5 wt %, orabout 0.1 wt % to 5 wt %, or about 0.2 wt % to 5 wt %, or about 0.3 wt %to 5 wt %, or about 0.4 wt % to 5 wt %, or about 0.5 wt % to 5 wt %, orabout 0.6 wt % to 5 wt %, or about 0.7 wt % to 5 wt %, or about 0.8 wt %to 5 wt %, or about 0.9 wt % to 5 wt %, or about 1.0 wt % to 5 wt %, orabout 0.01 wt % to 4.5 wt %, or about 0.01 wt % to 4.0 wt %, or about0.01 wt % to 3.5 wt %, or about 0.01 wt % to 3.0 wt %, or about 0.01 wt% to 2.5 wt %, or about 0.01 wt % to 2.0 wt %, or about 0.01 wt % to 1.5wt %, or about 0.01 wt % to 1.0 wt %, or about 0.5 wt % to 4 wt %, orabout 0.5 wt % to 3 wt %, or about 0.5 wt % to 2 wt % based on the totalweight of the emulsion.

In some embodiments, the emulsions include one or more oil fieldadditives conventionally used in hydraulic fracturing or post-primaryfracturing of subterranean hydrocarbon-containing formations. In someembodiments, the additives are added to the emulsions and the resultingadditive containing emulsions are stable, or even shelf stable. In otherembodiments, the additives are not added directly to the emulsions, butrather are added to the subterranean reservoir contemporaneously withdilution of the emulsions to form fracturing fluids. Suitable additivesinclude viscosifying agents, solvents, alkali, flow back aids,non-emulsifiers, corrosion inhibitors, scale inhibitors, biocides,friction reducers, emulsion breakers, and proppants (e.g., sand oraluminum oxide particles). Suitable corrosion inhibitors includeimidazoline and quaternary ammonium compounds and functionalizedcompounds and polymers. Suitable scale inhibitors include phosphonatecompounds and acrylated polymers. In some embodiments, one or more suchadditives are added at an amount that is less than 1 percent by weightof the emulsion. In other embodiments, the additives added duringdilution of an emulsion are employed at about 1 ppm to 500 ppm in thefracturing fluid formed during the dilution, for example about 2 ppm to400 ppm, or about 3 ppm to 300 ppm, or about 4 ppm to 200 ppm, or about5 ppm to 100 ppm of one or more additives.

The emulsions of the invention are stable. In some embodiments, theemulsions of the invention are shelf stable. In some such embodiments,the emulsions are shelf stable for about 6 months to two years, or about6 months to one year. In some embodiments, the total concentration ofsurfactants in the emulsion, or a diluted emulsion, is referred to asthe concentration of “actives” in a composition of the invention.

Compositions of the Second Embodiment

Disclosed herein are compositions for use in the recovery of hydrocarboncompounds from hydrocarbon-containing subterranean fractured rockformations. In a second embodiment, the compositions are emulsions. Insome such embodiments, the emulsions are microemulsions. The emulsionsof the second embodiment comprise, consist essentially of, or consist of(1) a coupling agent, (2) one or more water soluble or dispersiblenonionic surfactants, (3) at least one zwitterionic surfactant, (4) atleast one anionic surfactant, (5) optionally one or more additionalionic surfactants, and (6) water. In some embodiments, the totalconcentration of surfactants in a composition of the invention isreferred to as the concentration of “actives”.

The coupling agent employed in the compositions of the second embodimentcomprises, consists essentially of, or consists of water misciblesolvents and mixtures of two or more water miscible solvents. Thecoupling agents do not destabilize the emulsions. In some embodiments,the coupling agents increase stability of the emulsions. In someembodiments, the coupling agent is fully miscible with water; that is,all possible coupling agent:water ratios are miscible. In otherembodiments, the coupling agent is miscible with water at least up toabout 20:1 water:coupling agent by volume, or about 10:1, about 9:1,about 8:1, about 7:1, about 6:1, about 5:1, about 4:1, about 3:1, about2:1, about 1:1, about 1:2, about 1:3, about 1:4, about 1:5, about 1:6,about 1:7, about 1:8, about 1:9, about 1:10, about 1:20 water:couplingagent by volume, or ranges between any of these two ratios, such asbetween about 20:1 and 1:20, between 5:1 and 2:1, and the like.

Suitable coupling agents comprise, consist essentially of, or consist oflinear, branched, or cyclic aliphatic alcohols having 1 to 6 carbonatoms, diols having 1 to 6 carbon atoms, alkyl ethers of alkyleneglycols wherein the alkyl moiety has 1 to 6 carbon atoms (e.g., ethyleneglycol mono-n-butyl ether) polyalkylene glycols, and mixtures thereof.Also useful as coupling agents are glycol and glycerol based acetals andketals, such as those formed from the condensation of e.g. glycerol withformaldehyde, acetone, or oxocarboxylic acids, semialdehydes, and estersthereof such as levulinic acid or an alkyl levulinate. Examples ofuseful coupling agents include methanol, ethanol, glycerol, and ethyleneglycol.

The total amount of coupling agents included in the emulsions of thesecond embodiment is about 0.1 wt % to 20 wt % based on the total weightof an emulsion, for example about 0.5 wt % to 20 wt %, or about 1.0 wt %to 20 wt %, or about 2.0 wt % to 20 wt %, or about 3.0 wt % to 20 wt %,or about 4.0 wt % to 20 wt %, or about 5.0 wt % to 20 wt %, or about 6.0wt % to 20 wt %, or about 7.0 wt % to 20 wt %, or about 8.0 wt % to 20wt %, or about 9.0 wt % to 20 wt %, or about 10 wt % to 20 wt %, orabout 0.1 wt % to 19 wt %, or about 0.1 wt % to 18 wt %, or about 0.1 wt% to 17 wt %, or about 0.1 wt % to 16 wt %, or about 0.1 wt % to 15 wt%, or about 0.1 wt % to 14 wt %, or about 0.1 wt % to 13 wt %, or about0.1 wt % to 12 wt %, or about 0.1 wt % to 11 wt %, or about 0.1 wt % to10 wt %, or about 5 wt % to 20 wt %, or about 5 wt % to 15 wt % based onthe total weight of the emulsion.

The nonionic surfactant employed in the compositions of the secondembodiment comprises, consists essentially of, or consists of onealkoxylated alcohols, alkoxylated alkylphenols, glycerol esters, glycolesters, polyethylene glycol esters, polyglycerol esters, and sorbitolesters, and combinations of these. In some embodiments, the nonionicsurfactant is one or more surfactants selected from the groupcomprising, consisting essentially of, or consisting of alkoxylatedalcohols and alkoxylated alkyl phenols having an HLB greater than about10, for example about 10 to 20, or about 10 to 18, or about 10 to 16, orabout 10 to 14, or about 11 to 20, or about 11 to 18, or about 11 to 17,or about 11 to 16, or about 11 to 15, or about 11 to 14, or about 11 to13, and mixtures of these compounds. In embodiments, the alkoxylatedalcohols include ethoxylated, propoxylated, and ethoxylated propoxylatedalcohols wherein the alcohols include 4 to 10 carbons in linear,branched, or cyclic conformation and the alkoxy functionality includesan average of 4 to 12 moles of ethylene oxide, propylene oxide, or acombination thereof. In some embodiments, the nonionic surfactant is analkoxylated C6 alcohol.

The amount of the nonionic surfactant employed in the emulsions of thesecond embodiment totals about 5 wt % to to 15 wt % based on the totalweight of an emulsion, or about 6 wt % to 15 wt %, or about 7 wt % to 15wt %, or about 8 wt % to 15 wt %, or about 9 wt % to 15 wt %, or about 5wt % to 14 wt %, or about 5 wt % to 13 wt %, or about 5 wt % to 12 wt %,or about 5 wt % to 11 wt %, or about 5 wt % to 10 wt %, or about 6 wt %to 12 wt %, or about 7 wt % to 11 wt %, or about 8 wt % to 10 wt % basedon the total weight of the emulsion of the second embodiment.

The zwitterionic surfactant employed in the compositions of the secondembodiment comprises, consists essentially of, or consists of one ormore amphoteric molecules including at least one linear, branched orcyclic hydrocarbon moiety having 6 to 20 carbons, or about 8 to 18carbons, or about 10 to 16 carbons. Suitable zwitterionic surfactantsinclude betaines, sultaines, and alkyl amine oxides. Examples ofsuitable zwitterionic surfactants include cocoamidopropyl betaine,cocodimethyl betaine, N,N-dimethyl hexadecaneamine N-oxide, cocodimethylamine oxide, cocoamidopropyl hydroxysultaine, and dodecylamino-hydroxypropyl sultaines such as lauryl hydroxysultaine(n-dodecyl(2-hydroxy-3-sulfonatopropyl)dimethylammonium).

The amount of zwitterionic surfactants employed in the emulsions of thesecond embodiment totals about 10 wt % to 20 wt % based on the totalweight of an emulsion, for example about 10 wt % to 19 wt %, or about 10wt % to 18 wt %, or about 10 wt % to 17 wt %, or about 10 wt % to 16 wt%, or about 11 wt % to 20 wt %, or about 12 wt % to 20 wt %, or about 13wt % to 20 wt %, or about 14 wt % to 20 wt %, or about 15 wt % to 20 wt%, or about 16 wt % to 20 wt %, or about 12 wt % to 18 wt % based on thetotal weight of the emulsion.

The anionic surfactant employed in the emulsions of the secondembodiment includes at least one anionic moiety and has an HLB of about9 to 15, for example about 9 to 14, or about 9 to 13, or about 9 to 12,or about 9 to 11, or about 10 to 15, or about 11 to 15. Suitable anionicsurfactants include sulfonated esters of alkyl, aralkyl, oraryl-functional carboxylic acids wherein the ester groups arederivatives of linear or branched alcohols having about 4 to 15 carbons.Suitable examples of anionic surfactants include di-n-octyl sodiumsulfosuccinate (“DOSS” or “Aerosol OT”), sodium bis(2-ethylhexyl)sulfosuccinate, dicyclohexyl sodium sulfosuccinate, terminal (a-) andinternal olefin functional alkyl sulfonated surfactants,and alkylbenzenesulfonates.

The amount of the anionic surfactant employed in the emulsions of thesecond embodiment totals about 1 wt % to 10 wt % based on the totalweight of an emulsion, for example about 1 wt % to 9 wt %, or about 1 wt% to 8 wt %, or about 1 wt % to 7 wt %, or about 1 wt % to 6 wt %, orabout 1 wt % to 5 wt %, or about 2 wt % to 10 wt %, or about 3 wt % to10 wt %, or about 2 wt % to 9 wt %, or about 2 wt % to 8 wt %, or about2 wt % to 7 wt %, or about 2 wt % to 6 wt %, or about 2 wt % to 5 wt %,or about 2 wt % to 4 wt % based on the total weight of the emulsion.

The additional ionic surfactant optionally employed in the emulsions ofthe second embodiment comprises, consists essentially of, or consists ofone or more molecules having anionic, cationic or zwitterionicfunctionality and at least one linear, branched or cyclic hydrocarbonmoiety having 6 to 20 carbons, wherein the additional ionic surfactantis chemically different from the zwitterionic surfactant and the anionicsurfactant included in the composition of the second embodiment.Examples of suitable ionic surfactants include linear alkylbenzenesulfonic acid, alkyl benzene sulfonate, alkyl sulfonates, alkylsulfates, alkyl ether sulfates, alkyl ammonium halides, alkyl arylammonium halides, imidazolium, cocoamidopropyl betaine, cocodimethylbetaine, and alkyl amine oxides.

The amount of additional ionic surfactant employed in the emulsions ofthe second embodiment totals about 1 wt % to 20 wt % based on the totalweight of an emulsion, for example about 1 wt % to 19 wt %, or about 1wt % to 18 wt %, or about 1 wt % to 17 wt %, or about 1 wt % to 16 wt %,or about 1 wt % to 15 wt %, or about 1 wt % to 14 wt %, or about 1 wt %to 13 wt %, or about 1 wt % to 12 wt %, or about 1 wt % to 11 wt %, orabout 1 wt % to 10 wt %, or about 2 wt % to 10 wt %, or about 3 wt % to10 wt %, or about 4 wt % to 10 wt %, or about 5 wt % to 10 wt %, orabout 6 wt % to 10 wt %, or about 7 wt % to 10 wt %, or about 8 wt % to10 wt %, or about 10 wt % to 20 wt % based on the total weight of theemulsion.

In some embodiments, the emulsions of the second embodiment include oneor more oil field additives conventionally used in hydraulic fracturingor post-primary fracturing of subterranean hydrocarbon-containingformations. In some embodiments, the additives are added to theemulsions and the resulting additive containing emulsions are stable, oreven shelf stable. In other embodiments, the additives are not addeddirectly to the emulsions, but rather are added to the subterraneanreservoir contemporaneously with dilution of the emulsions. Suitableadditives include viscosifying agents, solvents, alkali, flow back aids,non-emulsifiers, corrosion inhibitors, scale inhibitors, biocides,friction reducers, emulsion breakers, and proppants (e.g. sand oraluminum oxide particles) as listed above. In some embodiments, one ormore such additives are added at an amount that is less than 1 percentby weight of the emulsion of the second embodiment. In otherembodiments, the additives added during dilution of an emulsion of thesecond embodiment are employed at about 1 ppm to 500 ppm in thefracturing fluid formed during the dilution, for example about 2 ppm to400 ppm, or about 3 ppm to 300 ppm, or about 4 ppm to 200 ppm, or about5 ppm to 100 ppm of one or more additives.

The emulsions of the second embodiment are stable. In some embodiments,the emulsions of the second embodiment are shelf stable. In some suchembodiments, the emulsions are shelf stable for about 6 months to twoyears, or about 6 months to one year.

Fracturing Fluids

The emulsions of the invention are diluted with a high total dissolvedsolids water source to form a fracturing fluid. The fracturing fluid isinjected into a subterranean hydrocarbon containing fractured rockformation, or reservoir, where it results in increased recovery ofhydrocarbon compounds from the subterranean hydrocarbon-containingformation. In some embodiments, the water source, the subterraneanenvironment, or both are at a high temperature, that is about 60° C. orhigher. In some embodiments, the emulsions of the first embodiment orthe second embodiment are combined with a high total dissolved solidswater source and any desired additives to produce a fracturing fluid ofthe invention contemporaneously with one or more injection processes.Such processes result in increased recovery of hydrocarbon compoundsfrom reservoirs. In some embodiments the reservoirs are characterized byone or more of low permeability, low porosity, and high temperature. Insome embodiments the water source used to dilute the emulsions of theinvention to form fracturing fluids are characterized by high totaldissolved solids, and in particular by a high concentration of divalentcations such as calcium and magnesium. In some embodiments the watersource is produced water. In some embodiments, the water source is acombination of produced water and a second water source such as seawater, brackish water, fresh water, tap water, and the like. Forexample, in some embodiments, the water source is about 50% to 100%produced water.

In embodiments, the fracturing fluids of the invention comprise, consistessentially of, or consist of about 10 wt % or less of an emulsion ofthe first embodiment or the second embodiment, and about 90 wt % or moreof a high total dissolved solids water source; optionally, thefracturing fluid further includes one or more of the additives asdescribed above. The fracturing fluids are formed by combining the watersource and the emulsion using conventional mixing procedures familiar tothose of skill in the art of forming hydraulic fracturing fluids. Nospecial methods or apparatuses are required to form the fracturingfluids of the invention from the emulsions of the first or secondembodiments. In some embodiments, a fracturing fluid of the inventioncomprises, consists essentially of, or consists of a combination of anemulsion of the first embodiment or of the second embodiment, a hightotal dissolved solids water source, and optionally one or moreadditives. In some embodiments, the water source is produced water. Insome embodiments, the produced water is high temperature.

In some embodiments, at the target (injectable) volume of produced waterin the fracturing fluid is about 90% to 99.999% of the fracturing fluidvolume, or about 91% to 99.999%, or about 92% to 99.999%, or about 93%to 99.999%, or about 94% to 99.999%, or about 95% to 99.999%, or about96% to 99.999%, or about 97% to 99.999%, or about 98% to 99.999%, orabout 99% to 99.999%, or about 90% to 99.99%, or about 90% to 99.9%, orabout 90% to 99%, or about 90% to 98%, or about 92% to 99.9%, or about94% to 99.9%, or about 95% to 99.9%, or about 98% to 99.9%, or about 99%to 99.9% of the fracturing fluid volume.

In embodiments, the water source employed to form the fracturing fluidsof the invention is a high total dissolved solids water source, whereinthe water source comprises about 4 wt % to 35 wt % substantiallynon-polymeric total dissolved solids. In some embodiments, the watersource is a high temperature, high total dissolved solids water source.In some embodiments where the water source includes high total dissolvedsolids, a substantial portion of the total dissolved solids are ioniccompounds. High total dissolved solids water sources include about 5 wt% to 35 wt %, or about 5 wt % to 32 wt %, or about 5 wt % to 30 wt %, orabout 5 wt % to 28 wt %, or about 5 wt % to 26 wt %, or about 5 wt % to24 wt %, or about 5 wt % to 22 wt %, or about 5 wt % to 20 wt %, orabout 6 wt % to 35 wt %, or about 7 wt % to 35 wt %, or about 8 wt % to35 wt %, or about 9 wt % to 35 wt %, or about 10 wt % to 35 wt %, orabout 12 wt % to 35 wt %, or about 14 wt % to 35 wt %, or about 16 wt %to 35 wt %, or about 18 wt % to 35 wt %, or about 20 wt % to 35 wt %, orabout 22 wt % to 35 wt %, or about 25 wt % to 35 wt %, or about 10 wt %to 32 wt %, or about 10 wt % to 30 wt %, or about 10 wt % to 28 wt %, orabout 10 wt % to 26 wt %, or about 10 wt % to 24 wt %, or about 10 wt %to 22 wt %, or about 10 wt % to 20 wt % non-polymeric solids. In someembodiments, the water source is produced water, brackish water, or seawater.

“Produced water” is an industrial term of art meaning water that flowsfrom a subterranean formation after release of pressure used to fracturethe subterranean rock. In some embodiments, the produced water iscontacted with an emulsion of the invention to dilute the emulsion, andeliminate the emulsion itself (forming a single phase composition) priorto or during subterranean injection. In some embodiments produced watercontains high levels of divalent ions and other ions that causeinstabilities when conventional emulsions are blended therewith.Substantial amounts of ions such as Cl, Na, Ca, Mg, Sr, Ba, or Fe areknown to cause instabilities in conventional fracturing fluids, that is,fracturing fluids formed from produced water and conventional emulsions.

In some embodiments, the water source contacting the emulsion, such assea water, brackish water, produced water, or combinations thereof withone or more additional water sources includes 300 ppm or more of one ormore ions. In some embodiments, the water source contacting the emulsioncontains one more of the following: about 300 ppm or more of Ca, forexample 500 ppm or more or even 3000 ppm or more of Ca; about 1100 ppmor more of Mg; about 300 ppm or more of Ba, for example about 500 ppm ormore of Ba; or about 85000 ppm Cl or more. It is an unexpected advantageof the present invention that stable fracturing fluids are formed fromthe emulsions of the invention by blending the emulsions with watersources containing 300 ppm or more of any one or more ions, such as Cl,Na, Ca, Mg, Sr, Ba, or Fe.

The fracturing fluids of the invention are stable in the presence of anyone or more of the following: about 300 ppm to 20,000 ppm Ca, or about500 ppm to 20,000 ppm Ca, or about 1000 ppm to 20,000 ppm Ca, or about2000 ppm to 20,000 ppm Ca, or about 3000 ppm to 20,000 ppm Ca, or about4000 ppm to 20,000 ppm Ca, or about 5000 ppm to 20,000 ppm Ca, or about6000 ppm to 20,000 ppm Ca, or about 7000 ppm to 20,000 ppm Ca, or about8000 ppm to 20,000 ppm Ca, or about 9000 ppm to 20,000 ppm Ca, or about10,000 ppm to 20,000 ppm Ca; about 300 ppm to 4000 ppm Mg, or about 400ppm to 4000 ppm Mg, or about 500 ppm to 4000 ppm Mg, or about 600 ppm to4000 ppm Mg, or about 700 ppm to 4000 ppm Mg, or about 800 ppm to 4000ppm Mg, or about 900 ppm to 4000 ppm Mg, or about 1000 ppm to 4000 ppmMg, or about 1500 ppm to 4000 ppm Mg, or about 2000 ppm to 4000 ppm Mg;about 300 ppm to 3000 ppm Ba, or about 500 ppm to 3000 ppm, or about 600ppm to 3000 ppm, or about 700 ppm to 3000 ppm, or about 800 ppm to 3000ppm, or about 900 ppm to 3000 ppm, or about 1000 ppm to 3000 ppm, orabout 1200 ppm to 3000 ppm, or about 1400 ppm to 3000 ppm, or about 1600ppm to 3000 ppm, or about 1800 ppm to 3000 ppm, or about 2000 ppm to3000 ppm Ba; about 300 ppm to 2500 ppm Sr, or about 400 ppm to 2300 ppm,or about 500 ppm to 2300 ppm, or about 600 ppm to 2300 ppm, or about 700ppm to 2300 ppm, or about 800 ppm to 2300 ppm, or about 900 ppm to 2300ppm, or about 1000 ppm to 2300 ppm, or about 1200 ppm to 2300 ppm, orabout 1400 ppm to 2300 ppm, or about 1600 ppm to 2300 ppm, or about 1800ppm to 2300 ppm Sr; about 5000 ppm to 100,000 ppm Na, or about 10,000ppm to 100,000 ppm, or about 20,000 ppm to 100,000 ppm, or about 30,000ppm to 100,000 ppm, or about 40,000 ppm to 100,000 ppm, or about 50,000ppm to 100,000 ppm, or about 60,000 ppm to 100,000 ppm, or about 70,000ppm to 100,000 ppm, or about 80,000 ppm to 100,000 ppm Na; about 100 ppmto 3000 ppm Fe, or about 200 ppm to 3000 ppm, or about 300 ppm to 3000ppm, or about 400 ppm to 3000 ppm, or about 600 ppm to 3000 ppm, orabout 800 ppm to 3000 ppm, or about 1000 ppm to 3000 ppm Fe; or about5000 ppm to 200,000 ppm Cl, or about 10,000 ppm to 200,000 ppm, or about20,000 ppm to 200,000 ppm, or about 40,000 ppm to 200,000 ppm, or about60,000 ppm to 200,000 ppm, or about 80,000 ppm to 200,000 ppm, or about100,000 ppm to 200,000 ppm, or about 110,000 ppm to 200,000 ppm, orabout 120,000 ppm to 200,000 ppm, or about 130,000 ppm to 200,000 ppm,or about 140,000 ppm to 200,000 ppm, or about 150,000 ppm to 200,000ppm, or about 160,000 ppm to 200,000 ppm, or about 170,000 ppm to200,000 ppm, or about 180,000 ppm to 200,000 ppm Cl.

In some embodiments, the water source contacting the emulsions of theinvention is a high total dissolved solids water source wherein thetotal amount of ions is at least about 4 wt % (40,000 ppm) and as muchas about 35 wt % (350,000 ppm); in such embodiments, the fracturingfluids of the invention are stable in the presence of high totaldissolved solids water sources. The fracturing fluids of the inventionare stable not only in the presence of ions in individual amountsgreater than 300 ppm, and in the presence of about 4 wt % to 35 wt %total dissolved solids, but further wherein the fracturing fluid isformed, injected, or otherwise employed at about 10° C. to 60° C., orabout 20° C. to 60° C., or about 30° C. to 60° C., or about 40° C. to60° C., or about 50° C. to 60° C., or at high temperature, that is about60° C. to 120° C., or about 70° C. to 120° C., or about 80° C., to 120°C., or about 90° C. to 120° C.

An analysis of produced water from various locations of subterraneanreservoirs reveals that the concentrations of ionic species varieswidely across different geographic locations where subterraneanreservoirs are located. A sampling of some ionic species from differentproduced waters is listed in Table 1. A produced water can have one ormore of the following: more than about 24,000 ppm Na content, more thanabout 2500 Ca content, more than about 70,000 Cl content, more thanabout 100 ppm Ba content, more than about 50 ppm Fe content, more thanabout 500 ppm Mg content, and more than about 1500 ppm carbonate(carbonic acid equivalent) content.

TABLE 1 Concentrations of various ionic species in produced waters.Concentration, ppm in various produced water Marcellus Wolfcamp WolfcampPermian Species Shale Bakken (sample 1) (sample 2) Basin Al <20 Ba 2900Ca 11000 13177 3660 5657 2993 Cl 184500 71600 84610 71596 Cr <5 Co 49 Cu<5 Fe <75 HCO₃ 278 49 Mg 940 1175 1350 2224 598 Mn <5 Mo <130 Ni <30 K190 5643 SO₄ 2350 1892 2028 SiO₂ <50 Na 24000 85322 40900 45060 42785 Sr2300 Ti <75 V <10 Zn <20 TOTAL 110000 289817 120138 139492 120000Notably, “TOTAL” means all dissolved solids, including but not limitedto the listed species. Blank = species not measured.

From an inspection of Table 1, it is clear that a fracturing fluid canbe made using produced water to dilute an emulsion prior to injectiononly if the emulsion produces a stable diluted fluid in the presence ofa range of dissolved ionic species as well as concentrations of thosespecies.

Additional challenges of employing produced water include substantialcompositional variability (see Table 1), variation in regulationsgoverning the storage, treatment, and disposal of produced water, andavailability of produced water at the source—that is, fresh water orother low total dissolved solids water sources are often not readilyavailable in the field, or are in short supply and cannot be used todilute the produced water. Shipping water to the field is not apractical solution due to cost. Thus, it is beneficial to hydraulicfracturing operations to enable the use of the substantially variablehigh total dissolved water sources available in the field.

We have found that the emulsions of the first embodiment and the secondembodiment are usefully employed to dilute with high total dissolvedsolids water, such as produced water, to form stable fracturing fluids.The fracturing fluids of the invention do not exhibit cloudiness,precipitation, phase separation, gelation, or any other behaviorattributable to instability. The fracturing fluids are thermally stablewhen subjected to underground conditions including temperatures of about60° C. to 120° C. Thus, the fracturing fluids made using produced waterare suitable for injection into a subterranean reservoir, where thefluids remain stable and do not cause precipitation, phase separation,or another behavior attributable to instability, while flowingunderground. This in turn results in optimal recovery of hydrocarbonsfrom the reservoir. The fracturing fluids of the invention areparticularly useful for increasing the yield of hydrocarbon productsfrom reservoirs where high temperatures are encountered undergroundsince no instabilities are encountered due to high temperature.

Methods

In embodiments, a method of the invention comprises, consistsessentially of, or consists of diluting the emulsions of the firstembodiment or the second embodiment with a high total dissolved solidswater source to form a fracturing fluid, injecting the fracturing fluidinto a well which is in contact with a subterraneanhydrocarbon-containing formation, and collecting one or more hydrocarboncompounds from the well. The fracturing fluid contains an amount of theemulsion of the invention that is effective for lowering the interfacialtension between fracturing fluid and the hydrocarbon compounds trappedwithin the formation. The fracturing fluid contains an amount of theemulsion of the invention that is effective for changing the wettabilityof the subterranean hydrocarbon-containing formation to recoverhydrocarbon compounds from the subterranean hydrocarbon-containingformation.

In embodiments, the injecting includes injecting into an undergroundreservoir wherein high temperatures are encountered. In some suchembodiments, the fracturing fluid becomes a high temperature fracturingfluid. Stated differently, the water source present in the fracturingfluid becomes a high temperature water source in addition to being ahigh total dissolved solids water source. We have found that theproperties desirably associated with the fracturing fluids of theinvention, as described herein, are maintained or are superior to thoseimparted by conventional fracturing fluids when subjected to hightemperature environments. In some embodiments, the undergroundtemperatures encountered by the injected fracturing fluids of theinvention is about 60° C. to 120° C., for example about 60° C. to 115°C., or about 60° C. to 110° C., or about 60° C. to 105° C., or about 60°C. to 100° C., or about 60° C. to 95° C., or about 60° C. to 90° C., oror about 70° C. to 120° C., or about 75° C. to 120° C., or about 80° C.to 120° C., or about 85° C. to 120° C., or about 90° C. to 120° C. Thefracturing fluids of the invention are stable at these hightemperatures. When subjected to high temperature conditions, thefracturing fluids of the invention maintain superior properties forproducing low interfacial tension with hydrocarbon compounds, lowadsorption onto rock surfaces, production of water-wettable rocksurfaces, and improved sweeping efficiency and proppant clean-upperformance under gravitational flow conditions when compared toconventional fracturing fluids.

The methods of the invention optionally include adding one or moreadditives to the emulsion or to the fracturing fluid prior to orcontemporaneously with formation of and/or injection of the fracturingfluid into a subterranean reservoir. Suitable additives includeviscosifying agents, solvents, alkali, flow back aids, non-emulsifiers,corrosion inhibitors, scale inhibitors, biocides, friction reducers,emulsion breakers, and proppants (e.g., sand or aluminum oxideparticles). Suitable corrosion inhibitors include imidazoline andquaternary ammonium compounds and functionalized compounds and polymers.Suitable scale inhibitors include phosphonate compounds and acrylatedpolymers. In some embodiments, the additives added during dilution of anemulsion to form a fracturing fluid. Generally, the additives areemployed at about 1 ppm to 500 ppm in the fracturing fluid, for exampleabout 2 ppm to 400 ppm, or about 3 ppm to 300 ppm, or about 4 ppm to 200ppm, or about 5 ppm to 100 ppm of one or more additives.

Upon injection of the fracturing fluids of the invention into asubterranean reservoir, rock surfaces contacted by the fracturing fluidschanges from oil-wettable to water-wettable. Yet the emulsion componentsof the fracturing fluids exhibit a low tendency to adsorb onto the rock.

The methods of the invention further include collecting one or morehydrocarbon compounds from the underground reservoir after injection ofthe fracturing fluid of the invention into the reservoir. The fracturingfluids of the invention are effective to change the wettability ofsubterranean rock, coated or even saturated with hydrocarbon compounds,from oil-wet to water-wet, or from mixed-wet to water-wet. Wettabilityof the subterranean rock is critical for obtaining maximum yield ofhydrocarbon, which can otherwise stay adhered to the surface of rock inthe form of a film. The large amount of subterranean rock surface areamakes the surface energy, that is, the wettability of the rock with oilvs. aqueous compositions, critical.

Wettability is determined by measuring contact angle of a fracturingfluid on oil-saturated rock. In some embodiments, the fracturing fluidsof the invention result in a contact angle of less than 90° whencontacted with rock previously soaked in hydrocarbon compounds such ascrude oil products. In some embodiments, after about 1 second of contactwith rock previously soaked in hydrocarbon compounds, contact angle of afracturing fluid of the invention is observed to be 70° or less, such asabout 5° to 70°, or about 10° to 70°, or about 20° to 70°, or about 30°to 70°, or about 40° to 70°, or about 5° to 65°, or about 5° to 60°, orabout 5° to 55°, or about 5° to 50°, or about 5° to 45°, or about 10° to60°, or about 10° to 50°, or about 20° to 50°, or about 30° to 50°. Insome embodiments, after about 10 seconds of contact with rock previouslysoaked in hydrocarbon compounds, contact angle of a fracturing fluid ofthe invention is observed to be 50° or less, such as about 5° to 50°, orabout 10° to 50°, or about 20° to 50°, or about 30° to 50°, or about 5°to 45°, or about 5° to 40°, or about 5° to 35°, or about 10° to 35°, orabout 10° to 30°, or about 20° to 40°, or about 25° to 40°. In someembodiments, after about 60 second of contact with rock previouslysoaked in hydrocarbon compounds, contact angle of a fracturing fluid ofthe invention is observed to be 40° or less, such as about 5° to 40°, orabout 7° to 40°, or about 10° to 40°, or about 15° to 40°, or about 20°to 40°, or about 5° to 35°, or about 5° to 30°, or about 5° to 25°, orabout 5° to 20°, or about 7° to 30°, or about 7° to 25°, or about 10° to25°.

Additionally, the emulsions of the invention exhibit low criticalmicelle concentration (cmc) when diluted with a water source. Theemulsions of the invention, that is the combined emulsion componentsalong with any additives employed - exhibit cmc of about 1 ppm to 50ppm, or about 1 ppm to 40 ppm, or about 1 ppm to 30 ppm, or about 1 ppmto 20 ppm, or about 1 ppm to 10 ppm, or about 2 ppm to 10 ppm in hightemperature, high total dissolved solids water sources, wherein measuredcmc values vary as a function of type and amount of solids dissolved inthe water source and temperature of the water. Without wishing to bebound by theory, we believe that a lower cmc leads to less freesurfactant concentration—particularly when the emulsions of theinvention are diluted to form fracturing fluids—less free surfactant inthe fracturing fluids leads to less adsorption onto rock surfaces.

We have further found that the fracturing fluids of the invention leadto reduced interfacial tension between the fracturing fluid and thehydrocarbon compounds present in the hydrocarbon containing subterraneanrock formation. For example, a fracturing fluid of the invention reducesinterfacial tension between a hydrocarbon compound mixture and a hightemperature high total dissolved solids water source an order ofmagnitude or more compared to the interfacial tension of a mixture ofthe hydrocarbon compound mixture and the high temperature, high totaldissolved solids water source without the fracturing fluid of theinvention.

In embodiments, the interfacial energy of a mixture of a hydrocarbon anda fracturing fluid of the invention is about 0.2 mN/m to 0.005 mN/m, orabout 0.15 mN/m to 0.005 mN/m, or about 0.12 mN/m to 0.005 mN/m, orabout 0.1 mN/m to 0.005 mN/m, or about 0.09 mN/m to 0.005 mN/m, or about0.08 mN/m to 0.005 mN/m, or about 0.07 mN/m to 0.005 mN/m, or about 0.06mN/m to 0.005 mN/m, or about 0.05 mN/m to 0.005 mN/m, or about 0.04 mN/mto 0.005 mN/m, or about 0.03 mN/m to 0.005 mN/m, or about 0.02 mN/m to0.005 mN/m, or about 0.2 mN/m to 0.007 mN/m, or about 0.2 mN/m to 0.009mN/m, or about 0.2 mN/m to 0.01 mN/m, or about 0.2 mN/m to 0.015 mN/m,or about 0.2 mN/m to 0.02 mN/m, or about 0.1 mN/m to 0.01 mN/m atambient temperatures, e.g. about 20° C. At temperatures between about50° C. and 100° C., the the interfacial energy of a mixture of ahydrocarbon and a fracturing fluid of the invention stays within thestated ranges. It is an unexpected advantage of the fracturing fluids ofthe invention that very low interfacial energy of a mixture of ahydrocarbon and a fracturing fluid of the invention is maintained evenat elevated temperatures. At such temperatures, the fracturing fluidalso contains high total dissolved solids. Yet the fracturing fluids arestable under such conditions and provide enhanced performance as aresult of these properties.

In a first example of enhanced performance, the interfacial energy of amixture of a hydrocarbon and a fracturing fluid of the invention remainssubstantially constant in high total dissolved solids water sources overa range of water source composition. This is so even when the watersource includes a substantial amount of divalent cations such ascalcium, magnesium, barium, and the like. This effect is beneficial forproviding predictable performance of the fracturing fluids over a rangeof conditions encountered in the field. Thus, in embodiments, theinterfacial energy of a mixture of a hydrocarbon and a fracturing fluidof the invention varies about ±0.08 mN/m or less over a range of watersources having between 0 and 35 wt % total dissolved non-polymericsolids, for example about ±0.08 mN/m to ±0.01 mN/m, or about ±0.07 mN/mto ±0.01 mN/m, or about ±0.06 mN/m to ±0.01 mN/m, or about ±0.05 mN/m to±0.01 mN/m, or about ±0.04 mN/m to ±0.01 mN/m, or about ±0.03 mN/m to±0.01 mN/m, or about ±0.02 mN/m to ±0.01 mN/m, or about ±0.08 mN/m to±0.02 mN/m, or about ±0.08 mN/m to ±0.03 mN/m, or about ±0.08 mN/m to±0.04 mN/m, or about ±0.06 mN/m to ±0.01 mN/m, or about ±0.06 mN/m to±0.02 mN/m, or about ±0.05 mN/m to ±0.01 mN/m, or about ±0.05 mN/m to±0.02 mN/m, or about ±0.04 mN/m to ±0.01 mN/m, or about ±0.04 mN/m to±0.02 mN/m over a range of water sources having between 0 and 35 wt %total dissolved non-polymeric solids.

In a second example of enhanced performance, the interfacial energy of amixture of a hydrocarbon and a fracturing fluid of the invention remainssubstantially constant in high total dissolved solids water sources overa range of temperatures. This is so even when the water source includesa substantial amount of divalent cations such as calcium, magnesium,barium, and the like. This effect is beneficial for providingpredictable performance of the fracturing fluids over a range ofconditions encountered in the field. Thus, in embodiments, theinterfacial energy of a mixture of a hydrocarbon and a fracturing fluidof the invention varies about ±0.08 mN/m or less when measured in watersources having between 0 and 35 wt % total dissolved non-polymericsolids and further wherein the temperature of the fracturing fluidranges from about 20° C. to 120° C., for example about ±0.08 mN/m to±0.01 mN/m, or about ±0.07 mN/m to ±0.01 mN/m, or about ±0.06 mN/m to±0.01 mN/m, or about ±0.05 mN/m to ±0.01 mN/m, or about ±0.04 mN/m to±0.01 mN/m, or about ±0.03 mN/m to ±0.01 mN/m, or about ±0.02 mN/m to±0.01 mN/m, or about ±0.08 mN/m to ±0.02 mN/m, or about ±0.08 mN/m to±0.03 mN/m, or about ±0.08 mN/m to ±0.04 mN/m, or about ±0.06 mN/m to±0.01 mN/m, or about ±0.06 mN/m to ±0.02 mN/m, or about ±0.05 mN/m to±0.01 mN/m, or about ±0.05 mN/m to ±0.02 mN/m, or about ±0.04 mN/m to±0.01 mN/m, or about ±0.04 mN/m to ±0.02 mN/m when measured in watersources having between 0 and 35 wt % total dissolved non-polymericsolids and further wherein the temperature of the fracturing fluidranges from about 20° C. to 120° C.

In a third example of enhanced performance, despite being effective tolower the interfacial tension between a hydrocarbon compound mixture anda high total dissolved solids water source, the fracturing fluids of theinvention do not induce formation of emulsions with hydrocarboncompounds when injected into subterranean reservoirs. As a measure ofthis property, we have found that where equal parts of a fracturingfluid of the invention is thoroughly mixed with a hydrocarbon compoundor mixture thereof using a high shear mixing apparatus designed to formemulsions, the mixture separates rapidly once shear is stopped. In someembodiments, such mixtures separate completely within about 1 minute to5 minutes, or about 1 minute to 4 minutes, or about 1 minute to 3minutes, or about 2 minutes to 5 minutes, or about 2 minutes to 4minutes.

Further, the fracturing fluids exhibit improved sweeping efficiency andproppant clean-up performance under gravitational flow conditions whencompared to conventional fracturing fluids. Thus, the fracturing fluidsof the invention substantially increase the yield of hydrocarboncompounds and mixture thereof, such as crude oil or shale oil, fromunderground reservoirs when injected therein when compared toconventional compositions. Water saturation of sand type proppants, forexample, is reduced by employing the fracturing fluids. In embodiments,saturation of proppant silica sand after treatment with the fracturingfluids of the invention followed by gravity assisted draining is lessthan about 70 wt % fracturing fluid based on the weight of the sand, forexample about 70 wt % to 20 wt %, or about 70 wt % to 25 wt %, or about70 wt % to 30 wt %, or about 70 wt % to 35 wt %, or about 70 wt % to 40wt %, or about 70 wt % to 45 wt %, or about 70 wt % to 50 wt %, or about65 wt % to 20 wt %, or about 60 wt % to 20 wt %, or about 55 wt % to 20wt %, or about 50 wt % to 20 wt %, or about 45 wt % to 20 wt %, or about40 wt % to 20 wt %, or about 35 wt % to 20 wt %, or about 30 wt % to 20wt %, or about 50 wt % to 30 wt %, or about 40 wt % to 30 wt %. Theaverage flow rate of hydrocarbons recovered from the reservoir aftertreating with a fracturing fluid of the invention is increased at leastten-fold, or 10×, compared to the average flow rate obtained byconventional surfactants; in embodiments the average flow rate isincreased 10× to 50×, or 20× to 50×, or 30× to 50×, or even 40× to 50×compared to flow rate obtained by conventional surfactants. In oilbreakthrough testing as described in the Examples below, oil flow ratesas high as about 0.1 mL/min to 1 mL/min are obtained using thefracturing fluids of the invention, or about 0.2 mL/min to 1 mL/min, orabout 0.3 mL/min to 1 mL/min, or about 0.4 mL/min to 1 mL/min, or about0.5 mL/min to 1 mL/min, or about 0.1 mL/min to 0.9 mL/min, or about 0.1mL/min to 0.8 mL/min, or about 0.1 mL/min to 0.7 mL/min, or about 0.1mL/min to 0.6 mL/min, or about 0.1 mL/min to 0.5 mL/min are obtainedusing the fracturing fluids of the invention.

In some embodiments, the subterranean hydrocarbon-containing formationaddressed by the emulsions and fracturing fluids of the invention is asandstone reservoir or a carbonate reservoir. In some embodiments, theinjection is carried out after hydraulic fracturing of the well. Inother embodiments, the injection is carried out during hydraulicfracturing of the well. The methods of the invention are particularlyuseful when the reservoir has low permeability, low porosity, oil-wetwettability, high temperature, and/or high salinity, and/or when thereis a high concentration of divalent cations in the fracturing fluidand/or produced water.

The emulsions of the invention are also suitably employed in one or moresteam assisted gravity drainage (SAGD) processes. SAGD is an enhancedoil recovery technology for producing heavy crude oil and bitumen. It isan advanced form of steam stimulation in which a pair of parallelhorizontal wells are drilled into a subterranean reservoir, one a fewmeters above the other. High pressure steam is continuously injectedinto the upper wellbore to heat the oil and reduce its viscosity,causing the heated oil to drain into the lower wellbore, where it ispumped out. In such processes, the emulsions or fracturing fluids of theinvention are usefully injected along with the steam to affectwettability, surface tension, and the like.

Having described the invention in detail, it will be apparent thatmodifications and variations are possible without departing from thescope of the invention defined in the appended claims.

EXPERIMENTAL

The following non-limiting examples are provided to further illustratethe present invention.

Example 1

The following components were blended to form Emulsion 1:

Nonylphenol ethoxylates (HLB of about 13) 2.4 wt % Castor oil ethoxylate(HLB of about 11.5) 0.8 wt % Methanol 10.8 wt % Cocoamidopropyl betaine9.6 wt % Water 58.8 wt % Choline chloride 15.0 wt % C12-14 alcoholethoxylate (HLB of about 8) 0.2 wt % Ethylene oxide/propylene oxidecopolymer 0.8 wt % Polyethylene imine ethoxylate 1.0 wt %

Emulsion 1 was observed to be stable. Emulsion 1 was further observed tobe a microemulsion. Emulsion 1 was observed to be stable at 115° C.

The solubility of surfactant-containing compositions in brines wasdetermined to reduce the possibility of damage to a reservoir insubsequent field testing. This screening test ensures that no solidprecipitates when the composition comes into contact with a formationfluid or fracturing fluid.

Surfactant-containing compositions were prepared by adding thecompositions to Bakken produced water (27% total dissolved solids) toform aqueous mixtures having 0.2% concentration of actives. The mixtureswere monitored for stability at 115° C. and were observed forprecipitation and suspension formation. A mixture that remains visiblyclear is considered to have sufficient aqueous stability. The resultsare reported in Table 2.

TABLE 2 Surfactant stability in Bakken produced water at 115° C.Observed Product Type Stability Results C12 alcohol ethoxylate having anSeparated average of 14 EO Nonylphenol ethoxylate having more Separatedthan 12 EO Ethylene oxide/propylene oxide Separated copolymer having anaverage number of 14 repeat units C14-C16 olefin sulfonate SeparatedDicocodimethyl ammonium chloride Separated Emulsion 1 Clear Lignin(obtained from MeadWestvaco Separated of Richmond, VA) C12-C14 phosphateester Separated Castor oil ethoxylate having 20-40 EO Separated C12-C14alcohol ether sulfonate Separated

Example 2

A composition was formed according to Example 1. Then 120 ppm of aquaternized imidazoline surfactant (corrosion inhibitor), 150 ppm of a aphosphonate (scale inhibitor), and 120 ppm glutaraldehyde (biocide) wasadded to the composition to yield a shelf stable microemulsion, referredto as Emulsion 2.

Example 3

Bakken reservoir rock core plugs were weighed, saturated with Bakken oil(a hydrocarbon compound mixture) and stored for at least 4 days atambient pressure to achieve oil wet status. Then excess oil was wipedfrom the plugs, and the plugs were reweighed; the density of the oil wasdetermined in order to calculate the volume of oil taken up by the rockcores. The cores were then placed with all faces opened in glassimbibition cells having precision graduations in 0.1 mL. For each of thefollowing tests, two rock core plugs were tested.

An aliquot of Emulsion 1 was diluted to 0.1 wt % solids (that is, atotal of 0.1 wt % of all surfactants combined) with a 4 wt % brinesolution to form Fracturing Fluid 1. The imbibition cells were filledwith a volume of the diluted Emulsion 1, then placed in a heated bathset at a temperature of 115° C. Displaced oil from the plugs formed alayer on top of the diluted Emulsion 1 in the cells, quantifiable asdisplaced volume. The cells were allowed to remain in the heated bathfor up to 500 hours or until displacement of oil, measured by the volumegraduations of the imbibition cells, was observed to stop. The volume ofoil measured was used to calculate the % Original Oil in Place (OOIP)oil recovery, which is the percent of oil volume measured in the test asa percent of the volume of oil taken up by the rock cores prior toinitiation of the test. Table 2 shows the oil recovery results as volumeof oil displaced.

The experiment was repeated with Emulsion 2, diluted to 0.1% solids in4% brine to form Fracturing Fluid 2. A comparative experiment was runusing 4% brine alone. Then the experiment was repeated using 0.1 wt % ofvarious surfactants dissolved in 4% brine. The sulfobetaine is laurylsulfobetaine, which is described in International Publication WO

2014/088817. The alcohol ether sulfonate is oleyl alcohol ethersulfonate, as described in U.S. Pat. No. 7,629,299. Results are shown inTable 3.

TABLE 3 % Original Oil in Place (OOIP) for the listed materials at 115°C. % OOIP Alcohol Sulfo- ether Time, betaine, sulfonate, FracturingFracturing 4% hr 0.1 wt % 0.1 wt % Fluid 1 Fluid 2 brine 0 0 0 0 0 0 0.50.49 17.98 0 1 1.96 22.48 0 2 22.48 2.07 3 29.44 22.48 2.07 4 22.48 2.075 29.44 22.48 2.07 6 22.48 2.07 7 22.48 2.07 8 34.35 31.47 2.07 24 9.820.35 39.25 31.47 2.07 48 9.8 20.35 39.25 33.72 2.07 72 15.68 20.3538.21 2.07 96 19.6 20.35 39.25 38.21 2.07 120 19.6 20.35 39.25 38.212.07 144 21.56 20.35 39.25 40.46 2.07 168 21.56 20.35 39.25 42.71 2.07192 21.56 20.35 39.25 42.71 2.07 216 21.56 20.35 42.71 2.07 240 21.5620.35 42.71 2.07 264 21.56 20.35 42.71 2.07 288 21.56 20.35 42.71 2.07312 21.56 20.35 42.71 2.07 (blank = not tested.)

Example 4

The procedure of Example 3 was repeated with Emulsion 2, except thatEmulsion 2 was diluted to 0.01 wt % solids with 4% brine to formFracturing Fluid 3. Results of oil displacement are shown in Table 4.

TABLE 4 % OOIP for Fracturing Fluid 3 at 115° C. Time, % hr OOIP 0 0 0.519.01 1 34.23 2 34.23 3 38.03 4 38.03 5 38.03 6 38.03 7 8 24 41.83 4841.83 72 41.83

Example 5

Bakken cores were saturated with the Bakken oil at 900 psi (6205 kPa),115° C. for 7 days or longer, then the surface oil was wiped off. A dropof a test material was placed on the core and the contact angle wasmeasured as a function of time after drop placement using a goniometer.A comparative experiment was run with 4% brine alone. Additionally, thesulfobetaine and alcohol ether sulfonate employed in Example 2 wereadded at 0.1 wt % in 4% brine and contact angle measurements carried outwith these surfactants solutions. All measurements were made at 25° C.Results are shown in Table 5.

TABLE 5 Contact angle at 25° C. as a function of time for the indicatedmaterials deposited on the surface of Bakken cores saturated with Bakkenoil. Contact angle, ° Material 0.1 1 3 10 60 80 120 150 tested sec secsec sec sec sec sec sec 4% brine 121.6 120.2 111.3 101.4 91.6 87.7 85.785.6 Fracturing 47.0 44.0 39.2 32.6 17.7 13.0 7.1 4.6 Fluid 1 Alcoholether 80.2 78.5 75.4 67.2 45.9 42.4 37.6 33.2 sulfonate Sulfobetaine75.0 73.3 69.6 60.8 43.8 41.4 38.5 36.4

Example 6

Critical micelle concentration at 80° C. was determined for Emulsion 1by measuring the surface tension as a function of surfactantconcentration at 80° C. using a Kriiss Tensiomer K-100 (obtained fromKriiss GmbH of Hamburg, Germany). As a comparative example, thesulfobetaine employed in Example 2 was also measured. Table 6 shows theresults of critical micelle concentration (cmc) measurements.

TABLE 6 Critical Micelle Concentration at 80° C. cmc, Product ppmEmulsion 1 actives in tap water  8-18 Emulsion 1 actives in 22% brine2-5 Emulsion 1 actives in 4% brine  6-10 Sulfobetaine, in tap water400-900

Example 7

This test was performed to compare the ability of various materials toprevent emulsion formation when contacted with residual oil. Variousmaterials were added to 25 ml of 4% KCl having pH adjusted to 11. Twentyfive (25) ml of 4% KCl containing a test material was mixed with twentyfive (25) ml of oil obtained from Bakken and blended at 14,000 rpm in aWaring Blender at 90° C. for 1 minute. The mixture was then poured intoa 6-oz glass prescription bottle to observe the water breakout from theemulsion. Table 6 shows the results of the observations, wherein 100%breakout indicates complete separation of the liquids. The sulfobetaineand the alcohol ether sulfonate are the same materials as employed inExample 2.

An emulsion was formed that was the same as Emulsion 1, except that noC12-14 alcohol ethoxylate was included. The emulsion is Emulsion 3.Emulsion 3 was tested according to the above procedure and the resultsare reported in Table 7.

TABLE 7 Emulsion 3 breakout at 90° C. Gallons of Material % BreakoutMaterial added per 1000 gallons of 1 2 3 to brine brine, based on activemin min min None 0 44 93 93 Emulsion 1 1 85 96 100 Alcohol ether 1 1 2 2sulfonate Sulfobetaine 1 50 60 67 Emulsion 3 1 33 50 67

Example 8

Emulsion 1 was diluted to various concentrations in 4% brine and 22%brine against Bakken oil at 80 C. Interfacial tension (IFT) was measuredfor the diluted Emulsion 1 using a spinning drop tensiometer. Table 8shows the interfacial tension (IFT) of Emulsion 1 as a function of theconcentration of Emulsion 1 actives.

TABLE 8 IFT of Emulsion 1 actives against Bakken oil at 80° C. Emulsion1 Emulsion 1 in 4% brine, IFT, in 22% brine, IFT, ppm actives mN/m ppmactives mN/m 0 14.23 0 22.16 1 12.51 1 16.09 5 5.53 5 10.95 10 4.52 108.28 20 3.17 20 2.18 30 1.53 30 1.93 50 0.75 50 1.10 100 0.71 100 1.00300 1.31 300 1.72 1000 1.54 1000 1.45

Example 9

The components shown in Table 9 were blended to form Emulsions 4-10, C1(control), and C2 (control). The blended components formedmicroemulsions at ambient temperature.

TABLE 9 Components of Emulsions 4-9, C1, and C2. Component Manufacturer,Amount, Component Type if applicable wt % Emulsion 4 Tap water water61.5 Methanol coupling agent 16.3 BIO-SOFT ® N91-8 nonionic StepanCompany 5.4 (ethoxylated alcohol of Northfield, IL [C9-C11 - 8 EO])BIO-SOFT ® N1-5 nonionic Stepan 5.4 (ethoxylated alcohol [C11 - 5 EO])TORNADOL ® 1-7 nonionic Air Products and 2.7 Chemicals, Inc. ofAllentown, PA ARQUAD ® 2C-75 cationic Akzo Nobel N.V. 8.6 of Amsterdam,the Netherlands Emulsion 5 PETROSTEP ® SB zwitterionic Stepan Company15.9 Ethoxylated alcohol nonionic Huntsman 9.5 [C6, 15 EO] Corporationof The Woodlands, TX AEROSOL OT-70 anionic Cytec Industries, 3.1 PG Inc.of West Paterson, NJ Glycerol coupling agent 6.4 Tap water water 65.0Emulsion 6 PETROSTEP ® SB zwitterionic Stepan 11.1 Ethoxylated alcoholnonionic Huntsman 11.1 [C6, 15 EO] AEROSOL ® OT-70 anionic Cytec 4.5 PGGlycerol coupling agent 4.5 Tap water water 68.8 Emulsion 7 PETROSTEP ®SB zwitterionic Stepan 15.9 Ethoxylated alcohol nonionic Huntsman 9.6[C6, 15 EO] AEROSOL OT-70 anionic Cytec 1.6 PG AEROSOL MA-80 anionicCytec 1.4 Glycerol coupling agent 3.2 Methanol coupling agent 3.2 Tapwater water 65.1 Emulsion 8 SERDOX ® [C11-9 nonionic Elementis 24.0 EO]Specialties, Inc., East Windsor, NJ ARQUAD ® 2C-75 cationic Akzo Nobel1.4 Methyl cationic 10.5 tris(2-hydroxyethyl) ammonium chloride Tapwater water 64.2 Emulsion 9 PETROSTEP ® SB zwitterionic Stepan 21.4Ethoxylated alcohol nonionic Huntsman 4.0 [C6, 15 EO] AEROSOL ® OT-70anionic Cytec 4.3 PG Methanol coupling agent 10.0 Tap water water 60.4Emulsion 10 MACKAM ® zwitterionic Solvay Novecare 20 LSB-50 Ethoxylatedalcohol nonionic Huntsman 4 [C6 - 15 EO] AEROSOL OT-70 anionic CytecIndustries, 5 PG Inc. Methanol coupling agent 10 Tap water water 61Emulsion C1 Ethoxylated alcohol nonionic 12.0 [C11 - 9 EO] Dicocodimethyl cationic 0.7 ammonium chloride Tap water water 87.3 Emulsion C2Ethoxylated alcohol nonionic 24.0 [C11 - 9 EO] Dicoco dimethyl cationic1.4 ammonium chloride Choline chloride cationic 10.0 Tap water water64.6

Example 10

Stability of fracturing fluids formed from emulsions C1, C2, 4, 5, and 7was measured by diluting the emulsions with brine and observing thefracturing fluids at selected temperatures. Thus, fracturing fluids wereformed by diluting the emulsions to a total of 0.2 wt % of emulsion“actives” (components other than water) with either a 2 wt % totaldissolved solids (TDS) water source (synthetic Eagle Ford brine) or a 30wt % TDS water source (synthetic Bakken brine). The fracturing fluidswere held at 20° C., 55° C., 65° C., 75° C., or 90° C. for two weeks andthe appearance of the fluid was assessed. Results are shown in Table 10.“Unstable” for purposes of this experiment means any visible sign ofphase separation or precipitation.

TABLE 10 Stability test results for fracturing fluids (0.2 wt % solids)formed from emulsions C1, C2, 4, 5, and 7 in brine. Emulsion Brine,Temperature, ° C. No. wt % TDS 20 55 65 75 90 C1 2 S U U U U C1 30 S U UU U C2 2 S S S S S C2 30 S S U U U 4 2 S S S S S 4 30 S U U U U 5 2 S SS S S 5 30 S S S S S 7 2 S S S S S 7 30 S S S S S S = stable; U =unstable.

Example 11

Interfacial tension experiments were carried out on fracturing fluidsformed from Emulsions 5 and C1 using an M6500 spinning drop tensiometer(obtained from Grace Instrument Company of Houston, Tex.). Fracturingfluid samples were prepared by diluting the emulsion with a brinesolution at 1:1000 vol/vol emulsion:brine. The brine included 110,000ppm total dissolved solids (11 wt % TDS). Tensiometer readings wererecorded every 5 minutes over a 30 minute test period to evaluate theinteraction of the tested fracturing fluid with crude oil, condensate ormodel alkane oil at projected reservoir temperatures. The interfacialtension of the fracturing fluid derived from Emulsion C2 with Eagle Fordcondensate was found to be 1.007 mN/m at ambient temperature; theinterfacial tension of the fracturing fluid derived from Emulsion 5 withEagle Ford condensate was 0.012 mN/m at ambient temperature.

The test was repeated for Emulsions 4 and 8, wherein temperature wasvaried from 30° C. to 90° C. during the test. A plot of interfacialtension after 30 min equilibration at each target temperature is shownin FIG. 1.

The test was repeated for Emulsions 5 and 8, wherein measurements werecompared at 1:1000 vol:vol of the emulsion:2 wt % KCl and 1:500emulsion:2 wt % KCl. A semi-log scale plot of interfacial tension (after30 min equilibration at the target temperature) as a function oftemperature is shown in FIG. 2.

The test was repeated for Emulsions 5 and 8, wherein measurements werecompared at 1:1000 vol:vol of the emulsion:12 wt % KCl and 1:500emulsion:12 wt % KCl. A semi-log scale plot of interfacial tension(after 30 min equilibration at the target temperature) as a function oftemperature is shown in FIG. 3.

The test was repeated for Emulsions 5 and 8 wherein the dilutions were1:1000 emulsion:brine and for Emulsions 5, 8, and 10 wherein thedilutions were 1:500 emulsion:brine, wherein for all emulsions anddilutions the brine composition was varied between 2 wt % and 12 wt %KCl, and the entire test was conducted at 90° C. A semi-log scale plotof interfacial tension (after 30 min equilibration at 90° C.) as afunction of KCl concentration is shown in FIG. 4.

Example 12

Gravitational drainage column testing was carried out on on fracturingfluids formed from Emulsions 5, 10, and C1. This test was designed toevaluate the sweeping efficiency and proppant clean-up performance ofdifferent fracturing fluids under gravitational flow conditions. Thetest employs crude oil or a condensate, brine (synthetic or formation),100-mesh sand, and a fracturing fluid. Fracturing fluid samples wereprepared by diluting an emulsion with a brine solution at a ratio of1:1000 vol/vol or 1:500 vol/vol emulsion:brine. The column waspre-heated to the indicated temperature. The column pack was prepared byfilling the column with about 16.5 mL of the fracturing fluid to betested and slowly adding 60 grams of sand into the column. Then thecolumn was compacted using vibration to minimize the presence of airpockets and compact the sand in the column. After compacting, the levelof the fracturing fluid in the column was adjusted to extend to justabove the sand pack. Then the column was allowed to stand undisturbedfor 30 minutes or until the column reached the target temperature. Thentwo pore volumes of oil (˜33 mL) were added into the column, a valve atthe bottom of the column was open and a timer was started. Effluentflowing from the column was observed. The time when oil first appearedin the effluent was recorded as the time to breakthrough. The flow rateof oil after breakthrough was measured by recording the cumulative oilflowing out of the column after breakthrough and over about 30-60 min.Results are shown in Table 11.

TABLE 11 Gravitational drainage test results for fracturing fluidsformed from Emulsions C1 and 5. Fracturing Rate of oil Water Time to oilfluid flow after saturation breakthrough, eluted, breakthrough, of sand,Emulsion min. vol % mL/min wt % C1 >300 15 0.012 85  5 6.88 65 0.5 35 105 88.6 1.3 11.4

Notably, Emulsions 5 and 10 provide substantially lower water saturationand substantially higher rate of oil flow compared to Emulsion C1. Inthe field, these results translate to more complete water cleanup(improved final water quality) and lower fracturing fluid saturation ofthe subterranean reservoir.

Example 13

Thermal stability of Emulsions 8 and 10 was tested by measuring thesurface tension of each emulsion in 2% aqueous KCl at 300° F. (149° C.)at 200 psi (1379 kPa) as a function of time. Each emulsion was preparedat 0.2% by weight of surfactant solids in the 2% aqueous KCl solution.The initial surface tension value of each prepared emulsion was measuredby the Wilhemy plate method using a Kriiss Force Tensiometer K100. Eachprepared emulsion was then transferred into a a Teflon liner and eachTeflon liner was placed inside an aging cell constructed of grade 316stainless steel. Each aging cell was pressurized to 200 psi (1379 kPa)and then both cells were placed in an oven at 300° F. (149° C.). Samplesof each prepared emulsion were taken out periodically (every 3-4 days)and the surface tension value of each prepared emulsion was measured bythe Wilhemy plate method using a Kriiss Force Tensiometer K100. Thesurface tension values were monitored until a significant increase insurface tension was observed (i.e. when surface tension changed from 27mN/m to 60 mN/m). Plots of the surface tensions of the two preparedemulsions as a function of time are shown in FIG. 5 and the results areshown in Table 12.

TABLE 12 Surface tension measurements of prepared Emulsions 8 and 10. t,Surface Tension, Prepared Emulsion day mN/m Emulsion 10 in 2% KCl 025.23 4 25.26 7 25.22 14 24.89 18 25.07 21 25.98 28 31.56 35 34.58 4233.66 Emulsion 8 in 2% KCl 0 26.39 4 26.49 7 31.73 11 31.85 14 47.35 2152.17 28 51.34

Emulsion 10 shows improved thermal stability as judged by surfacetension stability over time at 300° F. (149° C.) and 200 psi (1379 kPa)in 2% KCl. The surface tension of prepared Emulsion 8 rose from aninitial value of 26.39 mN/m to 31.73 mN/m at 7 days, and at 14 days hadrisen to 47.35 mN/m, rising to over 50 mN/m after 21 days. In contrast,the surface tension of prepared Emulsion 10 did not rise over the first14 days: from an initial value of 25.23 mN/m, the surface tension ofprepared Emulsion 10 at 14 days was measured to be 24.89 mN/m, and hadonly rise to 25.98 mN/m at 21 days, 31.56 mN/m at 28 days, 34.58 mN/m at35 days, and 33.66 mN/m after 42 days.

The invention illustratively disclosed herein can be suitably practicedin the absence of any element which is not specifically disclosedherein. While the invention is susceptible to various modifications andalternative forms, specifics thereof have been shown by way of examples,and are described in detail. It should be understood, however, that theinvention is not limited to the particular embodiments described. On thecontrary, the intention is to cover modifications, equivalents, andalternatives falling within the spirit and scope of the invention asdescribed herein. In various embodiments, the invention suitablycomprises, consists essentially of, or consists of the elementsdescribed herein and claimed according to the claims.

Additionally each and every embodiment of the invention, as describedhere, is intended to be used either alone or in combination with anyother embodiment described herein as well as modifications, equivalents,and alternatives thereof.

What is claimed is:
 1. A composition comprising about 98 wt % to 99.999wt % of a water source comprising high total dissolved solids; one ormore oil phase surfactants, the oil phase surfactants characterized asnonionic and having a combined HLB of less than about 9; one or morecoupling agents; one or more water phase surfactants, wherein the waterphase surfactants are nonionic, soluble or dispersible in water, andchemically different from the one or more oil phase surfactants; one ormore ionic surfactants; and one or more clay stabilizers.
 2. Thecomposition of claim 1 wherein the water source comprises about 10 wt %to 35 wt % non-polymeric solids.
 3. The composition of claim 1 whereinthe water source is a high temperature water source.
 4. The compositionof claim 1 further comprising one or more additives, the additivescomprising one or more viscosifying agents, solvents, alkali, flow backaids, non-emulsifiers, friction reducers, breakers, crosslinking agents,biocides, proppants, or mixtures thereof.
 5. The composition of claim 1wherein the oil phase surfactant comprises one or more alkoxylatedalcohols, alkoxylated alkylphenols, glycerol esters, glycol esters,polyethylene glycol esters, polyglycerol esters, sorbitol esters, andmixtures thereof.
 6. The composition of claim 1 wherein the couplingagent comprises one or more linear, branched, or cyclic aliphaticalcohols having 1 to 6 carbon atoms, diols having 1 to 6 carbon atoms,alkyl ethers of alkylene glycols wherein the alkyl moiety has 1 to 6carbon atoms, polyalkylene glycols, and mixtures thereof.
 7. Thecomposition of claim 1 wherein the water phase surfactant comprises oneor more alkoxylated alcohols or alkoxylated alkyl phenols having an HLBgreater than about 10, and mixtures thereof.
 8. The composition of claim1 wherein the ionic surfactant comprises one or more alkylbenzenesulfonic acids, alkyl benzene sulfonates, alkyl sulfonates, alkylsulfates, alkyl ether sulfates, alkyl ammonium halides, alkyl arylammonium halides, imidazolium, cocoamidopropyl betaine, cocodimethylbetaine, alkyl amine oxides, and mixtures thereof.
 9. A compositioncomprising about 98 wt % to 99.999 wt % of a water source comprisinghigh total dissolved solids; one or more coupling agents, one or morewater soluble or dispersible nonionic surfactants, one or morezwitterionic surfactants, one or more anionic surfactants, andoptionally one or more additional ionic surfactants.
 10. The compositionof claim 9 wherein the water source comprises about 10 wt % to 35 wt %non-polymeric solids.
 11. The composition of claim 9 wherein the watersource is a high temperature water source.
 12. The composition of claim9 further comprising one or more additives, the additives comprising oneor more viscosifying agents, solvents, alkali, flow back aids,non-emulsifiers, friction reducers, breakers, crosslinking agents,biocides, proppants, or mixtures thereof.
 13. A method of increasingrecovery of crude oil from a subterranean hydrocarbon-containingformation, the method comprising: forming an emulsion, the emulsioncomprising a. one or more oil phase surfactants, the oil phasesurfactants characterized as nonionic and having a combined HLB of lessthan about 9, b. a coupling agent, c. one or more water phasesurfactants, wherein the water phase surfactants are nonionic, solubleor dispersible in water, and chemically different from the one or moreoil phase surfactants, d. one or more ionic surfactants, e. one or moreclay stabilizers, and f. about 40 wt % to 80 wt % water; contacting theemulsion with a high total dissolved solids water source to form afracturing fluid; injecting the fracturing fluid into a subterraneanhydrocarbon-containing formation; and collecting a hydrocarbon from thesubterranean hydrocarbon-containing formation.
 14. The method of claim13 wherein a portion of the subterranean hydrocarbon containingformation at a temperature of about 60° C. to 120° C.
 15. The method ofclaim 13 wherein the water source comprises about 5 wt % to 30 wt %total dissolved solids.
 16. The method of claim 13 wherein thecontacting is carried out contemporaneously with the injecting.
 17. Themethod of claim 13 wherein the contacting is carried out prior to theinjecting.
 18. The method of claim 13 wherein the injecting is into afirst wellbore connected to the subterranean hydrocarbon-containingformation, and the collecting is from a second wellbore that isconnected to the subterranean hydrocarbon-containing formation.
 19. Themethod of claim 13 wherein the injecting is into a wellbore connected tothe subterranean hydrocarbon-containing formation, and the collecting isfrom the same wellbore.
 20. A method of increasing recovery of crude oilfrom a subterranean hydrocarbon-containing formation, the methodcomprising: forming an emulsion, the emulsion comprising one or morecoupling agents, one or more water soluble or dispersible nonionicsurfactants, one or more zwitterionic surfactants, one or more anionicsurfactants, and optionally one or more additional ionic surfactants;contacting the emulsion with a high total dissolved solids water sourceto form a fracturing fluid, the fracturing fluid comprising about 98 wt% to 99.99 wt % of the high total dissolved solids water source;injecting the fracturing fluid into a subterraneanhydrocarbon-containing formation; and collecting a hydrocarbon from thesubterranean hydrocarbon-containing formation.
 21. The method of claim20 wherein at least a portion of the subterranean hydrocarbon containingformation at a temperature of about 60° C. to 120° C.
 22. The method ofclaim 20 wherein the water source comprises about 5 wt % to 30 wt %total dissolved solids.
 23. The method of claim 20 wherein thecontacting is carried out contemporaneously with the injecting.
 24. Themethod of claim 20 wherein the contacting is carried out prior to theinjecting.
 25. The method of claim 20 wherein the injecting is into afirst wellbore connected to the subterranean hydrocarbon-containingformation, and the collecting is from a second wellbore that isconnected to the subterranean hydrocarbon-containing formation.
 26. Themethod of claim 20 wherein the injecting is into a wellbore connected tothe subterranean hydrocarbon-containing formation, and the collecting isfrom the same wellbore.